(2) OAR 860-084-0100 through
860-084-0450 (the “Solar Photovoltaic Pilot Programs”) govern implementation
of pilot programs to demonstrate the use and effectiveness of volumetric incentive
rates and payments for electricity delivered from solar photovoltaic energy systems.

(3) Upon request or its own
motion, the Commission may waive any of the Division 084 rules for good cause shown.
A request for waiver must be made in writing, unless otherwise allowed by the Commission.

(1) “Contracted
system” means an eligible system under contract in the solar photovoltaic
pilot program associated with a single meter.

(2) “Electric
company” has the meaning given that term in ORS 757.600.

(3) “Eligible
consumer” means a retail electricity consumer receiving service at the property
where the solar photovoltaic system will be installed.

(4) “Eligible
energy” or “eligible generation” means the kilowatt-hours that
may be paid at the volumetric incentive rate. For the net metering option of the
pilot program, eligible energy is equal to the usage of the retail electricity consumer
in the year that the energy is generated by the eligible system. In a given month,
this eligible energy is equal to the actual usage of the retail electricity consumer
for that month. For the bidding option of the pilot program, eligible energy equals
actual generation, net of system requirements.

(5) “Eligible
participant” or “participant” means an eligible consumer who has
signed a contract with the electric company and is participating in the pilot program.
A regulated utility is not an eligible participant in pilot programs.

(6) “Eligible
system” means a qualifying system that meets the requirements of OAR 860-084-0120.

(7) “Equipment
package” means a group of components connecting an electric generator with
an electric distribution system and includes all interface equipment including switchgear,
inverters, or other interface devices. An equipment package may include an integrated
generator or electric production source.

(8) “Excess
energy” or “excess generation” means the kilowatt-hours generated
in excess of actual annual usage under the net metering option of the volumetric
incentive rate pilot program. In a given month, excess energy means kilowatt-hours
generated in excess of monthly usage.

(9) "IEEE
standards" means the standards published in the 2003 edition of the Institute of
Electrical and Electronics Engineers (IEEE) Standard 1547, titled “Interconnecting
Distributed Resources with Electric Power Systems,” approved by the IEEE SA
Standards Board on June 12, 2003, and in the 2005 edition of the IEEE Standard 1547.1,
titled “IEEE Standard Conformance Test Procedures for Equipment Interconnecting
Distributed Resources with Electric Power Systems,” approved by the IEEE SA
Standards Board on June 9, 2005.

(10) “Installed
System” means an eligible system that is completely built, has passed final
electrical inspection by the local authority with jurisdiction, and is pending completion
of utility work to connect it to the utility grid.

(14) “Pilot
capacity limit” means the maximum installed capacity that each electric company
may contract during the pilot program.

(15) “Pilot
year” means each twelve-month period of the solar photovoltaic pilot program
beginning on April 1 and ending on March 31.

(16) “Qualifying
assignee” or “assignee” means a person to whom a retail electricity
consumer may assign volumetric incentive rate payments under the standard contract.
An electric company or its affiliate or any other regulated utility is not a qualifying
assignee. Qualifying assignees include, but are not limited to:

(b) A
company or individual who enters into a financial agreement with a retail electricity
consumer to own and operate a solar photovoltaic system on behalf of the retail
electricity consumer in return for compensation;

(c) A
company or individual who contracts with the retail electricity consumer to locate
a solar photovoltaic system on property owned by the retail electricity consumer;
or

(d) Any
party identified by the retail electricity consumer to receive payments that the
electric company is obligated to pay to the retail electricity consumer.

(17) “Qualifying
third party” or “third party” means a party who is the owner or
operator of a solar photovoltaic system installed under the pilot program but who
is not the retail electricity consumer at that location. An electric company is
not a qualifying third party under the pilot programs.

(18) “Reservation
start date” means the date the retail electricity consumer is notified of
securing capacity through a capacity reservation process and of the start and expiration
dates for that capacity reservation. The reservation start date initiates the time
to interconnection agreement.

(19) “Retail
electricity consumer” means a consumer who is a direct customer of the electric
company and is the end user of electricity for specific purposes, such as heating,
lighting, or operating equipment. Retail electricity consumers include direct access
consumers.

(21) “Time
to interconnection agreement” means the time between the reservation start
date and the date an eligible participant signs an interconnection agreement.

(22) “Volumetric
incentive payments” or “payments” mean the monthly amount that
an electric company pays to an eligible participant or assignee in the solar photovoltaic
pilot program for payable energy generated by a contracted system.

(23) “Volumetric
incentive rate” means the rate per kilowatt-hour paid by an electric company
to a retail electricity consumer or assignee for payable generation.

By January 1,
2020, each electric company must own or contract to purchase the capacity and output
of qualifying solar photovoltaic systems to meet and maintain the following minimum
solar photovoltaic capacity standards:

Individual solar
photovoltaic systems used to comply with the solar photovoltaic capacity standards
in OAR 860-084-0020 must have a nameplate generating capacity greater than or equal
to 500 kilowatts and less than or equal to 5 megawatts.

Measurement of Capacity under the Solar Photovoltaic Capacity Standard

(1) The capacity
of solar photovoltaic systems used to satisfy the requirements of OAR 860-084-0020
must be measured on the alternating current side of the system’s inverter.

(2) Each
electric company must convert nameplate capacity ratings reported by manufacturers
in terms of direct current watts under standard test conditions to an alternating
current rating in watts to account for inverter and other system component losses
and to account for the effect of normal operating temperature on solar module output.
This conversion will be calculated as 85 percent of the manufacturer’s nameplate
rating.

(1) By February
1, 2020, each electric company must file a report with the Commission demonstrating
compliance, or explaining in detail any failure to comply, with the solar photovoltaic
capacity standards in OAR 860-084-0020.

(2) The
report required in section (1) of this rule must include the following information
associated with each solar photovoltaic system:

(a) The
name of the facility;

(b) The
location of the facility;

(c) The
in-service date of the facility;

(d) The
manufacturer’s nameplate capacity rating;

(e) The
electric company’s capacity rating on the alternating current side of the
system’s inverter;

(f) The
execution date of any associated power purchase agreement; and

(g) The
contracted capacity and output delivery period of any associated power purchase
agreement.

An electric company may request recovery of its prudently incurred costs to comply with the solar photovoltaic capacity standard specified in OAR 860-084-0020 in an automatic adjustment clause proceeding filed at the Commission pursuant to ORS 469A.120.

Renewable Energy Certificates and Compliance with the Renewable Portfolio Standards

(1) Each renewable
energy certificate associated with the electricity produced by solar photovoltaic
systems used to meet the minimum solar photovoltaic capacity standards in OAR 860-084-0020
may be used to comply with the renewable portfolio standards established under ORS
469A.005 through 469A.120.

(2) Each
renewable energy certificate associated with the electricity produced by solar photovoltaic
systems may be counted twice to comply with the renewable portfolio standards established
under ORS 469A.005 through 469A.120, if the solar photovoltaic systems:

Each electric company must incorporate its plan to achieve, or exceed, and maintain the minimum solar photovoltaic capacity standards specified in OAR 860-084-0020 into its renewable portfolio standard implementation plans filed pursuant to OAR 860-083-0400.

(1) Each electric
company must establish pilot programs to demonstrate the use and effectiveness of
volumetric incentive rates and payments for electricity delivered from qualifying
solar photovoltaic systems.

(2) Each
electric company must offer a net metering option under the pilot program. This
option has the following characteristics:

(a) Eligible
systems installed on the customer side of the service meter;

(e) Capacity
of eligible systems sized to generate energy up to 90 percent of the actual usage
in the 12 most recent billing periods at the premises where the eligible system
will be installed;

(f) Capacity
of eligible systems with less than 12 billing periods of actual usage for existing
premises or new construction sized to generate energy up to 90 percent of the annual
usage by a similarly-situated customer or by a utility-provided load estimation
document as determined by the utility;

(g) Capacity
of eligible systems for irrigation or agriculture customers sized up to 90 percent
of average usage during a normal 12-month billing period as determined by the utility;
and

(h) The
methodologies used to estimate the usage if there is no sufficient actual usage
to size the system must be consistent with the methodologies used by the Energy
Trust of Oregon, the Oregon Department of Energy, or other methodologies acceptable
to the Commission.

(3) Each
electric company must offer a volumetric incentive rate bid option under the pilot
program. This option has the following characteristics:

(a) Volumetric
incentive rate paid to each retail electricity consumer is established by a successful
bid for capacity in the volumetric incentive rate pilot program; and

(1) Individual
solar photovoltaic systems eligible for the Solar Photovoltaic Pilot Programs must
have a nameplate generating capacity less than or equal to 500 kilowatts and must
be:

(a) In
compliance with the siting, design, interconnection, installation, and electric
output standards and codes required by the laws of Oregon;

(b) Installed
with meters or other devices to monitor and measure the quantity of energy generated;

(c) Permanently
installed in the State of Oregon by a retail electricity consumer of the electric
company;

(d) Installed
in the service territory of the electric company;

(e) First
operational and on-line after the launch of the pilot programs;

(f) Financed
without expenditures under ORS 757.612 (3)(b)(B) or tax credits under 469.160
or 469.185 through 469.225;

(g) Certified
by the residential electric consumer as constructed from new components (modules,
inverter, batteries, mounting hardware, etc.); and

(h) Compliant
with Commission quality and reliability requirements for solar photovoltaic systems
and system installation.

(2) Systems
uninstalled before the end of the contract term are not eligible for subsequent
volumetric incentive rates, other feed-in tariffs, or pilot programs during the
remainder of the original contract term. These systems cannot be reinstalled for
the purposes of entering a new contract under any solar photovoltaic pilot program,
volumetric incentive or other feed-in tariff program in the service territory of
any electric company in the State of Oregon during the original contract term of
the system, except that a system may be uninstalled and reinstalled at another location
under the same contract under the conditions in OAR 860-084-0280.

(3) Retail
electricity consumers submitting applications for a 500 kilowatt project are not
eligible to reserve capacity in the solar photovoltaic pilot program if the same
project is also competing for a purchased power agreement under the solar capacity
standard in OAR 860-084-0020.

(1) An electric
company must contract to provide an incentive for solar photovoltaic energy generated
from an eligible system owned by a retail electricity consumer who has been granted
a capacity reservation in the solar photovoltaic pilot program and has executed
all agreements with the electric company.

(2) Eligible
systems must be installed on the same property where the retail electricity consumer
buys electricity from the electric company.

(a) Eligible
systems with capacity reserved under the net metering option must be connected to
the customer side of the meter.

(b) Eligible
systems with capacity reserved under the competitive bidding option must connect
to the distribution feeder that services the customer’s property. The point
of common coupling may be located on the load side of the retail customer’s
existing electric service subject to utility approval and to the extent authorized
by law.

(c) If
cost effective, eligible systems may be connected at other distribution feeders
on the utility grid subject to utility approval and to the extent authorized by
law.

(3) A
retail electricity consumer may transfer its existing contract to another retail
electricity consumer eligible to contract with the electric company and residing
at the same address where the system is installed.

(4) Eligible
systems may be owned, operated, or owned and operated by qualifying third parties
if the eligible system is:

(a) Owned
by a qualifying third party as part of a loan agreement; or

(b) Owned
and operated by a qualifying third party on behalf of the retail electricity consumer;
or

(c) Operated
by a third party on behalf of the retail electricity consumer.

(5) The
electric company will own the rights to 100 percent of the renewable energy certificates
associated with the energy provided by the contracted systems. The electric company
may perfect the renewable energy certificates.

(1) An electric
company must allow a retail electricity consumer to assign payments to a single
qualifying assignee under standard contracts approved by the Commission and must
allow changes to assignment over the contract term.

(2) An
electric company may charge a reasonable fee for the assignment of payments for
account setup at the time that the standard contract is assigned. An electric company
may charge a reasonable fee for changes to assignment of payments over the contract
term.

(3) An
electric company must make volumetric incentive payments to the qualifying assignee
within 45 days of the retail electricity consumer’s prior billing period.

(4) Upon
request by the retail electricity consumer, the electric company may make the volumetric
incentive payments in one of the following methods:

(a) Full
payment for payable generation directly to the retail electricity consumer; the
retail electricity consumer is billed the standard monthly bill for electricity
purchased under the tariff; or

(b) Full
payment for payable generation net of the retail electricity consumer’s standard
monthly bill; the retail electricity consumer receives or pays the net amount; or

(c) Full
payment for payable generation to the qualified assignee identified on the standard
contract; the retail electricity consumer is billed separately for electricity purchased
under the tariff.

(5) The
retail electricity consumer is responsible for the minimum monthly charge and other
non-volumetric charges on the standard monthly bill.

(6) Payments
for payable generation will be held by the electric company until the amount accrued
per customer generator exceeds $25.00.

New capacity reservations will not be
accepted after March 31, 2016, or after the cumulative capacity of contracted systems
in pilot programs reaches 27.5 megawatts of nameplate capacity, whichever is earlier.

(1) For purposes of the Solar Photovoltaic Pilot Program, the capacity of solar photovoltaic energy is measured on the alternating current side of the system’s inverter.

(2) Each electric company must convert nameplate capacity ratings reported by manufacturers in terms of direct current watts under standard test conditions to an alternating current rating in watts to account for inverter and other system component losses and to account for the effect of normal operating temperature on solar module output. This conversion will be calculated as 85 percent of the manufacturer’s nameplate rating.

(1) Each electric company will receive a share of the total solar photovoltaic pilot program capacity as established by Commission order.

(2) An electric company may not solicit or accept additional capacity reservations for a solar photovoltaic pilot program once the company reaches 100 percent of its allocated solar photovoltaic pilot capacity limit.

(3) The Commission may consider requests to adjust each electric company’s solar photovoltaic pilot capacity limit by changing the allocation of the total solar photovoltaic pilot program capacity from those established at pilot program initiation.

(c) Electric
companies must notify winning lottery participants no later than three business
days after the close of the reservation application window. Deposits are due within
three days of this notification. Electric companies then have 15 days to confirm
that reservation applications conform to all program rules.

(d) In
any enrollment period, if the eligible capacity is not reserved through the lottery,
the remaining capacity will be made available on a first-come, first-served basis.
Any remaining capacity thereafter will roll over to the next capacity reservation
period unless otherwise directed by Commission order.

(4) The
following governs capacity distributed through a competitive bidding option:

(a) Electric
companies must issue a Request for Proposal for:

(A) Large-scale
bid option systems no later than 30 business days prior to April 1 of each pilot
year or as otherwise directed by Commission order; and

(B) Medium-scale
bid option systems no later than 30 business days prior to October 1 of each pilot
year or as otherwise directed by Commission order.

(b) Electric
companies must set the bidder response deadline for

(A) large-scale
bid option systems no later than April 1 of each pilot year and

(B) for
medium-scale bid option systems no later than October 1 of each pilot year or as
otherwise directed by Commission order.

(c) Electric
companies must award capacity to winning bidders no later than fifteen business
days after the bidder response deadline. Selection of winning bids must be based
solely on the bidder’s volumetric incentive rate bid.

(d) If
capacity remains available after all bids are awarded, then the remaining capacity
will roll over to the next appropriate bid-option enrollment window as defined by
subsection (4)(a) of this rule.

(e) A
medium- and large-scale bid-option reservation begins when the bidder receives notification
of a winning bid.

(5) Electric
companies must require a capacity reservation deposit of $500 or $20 per kilowatt
of the proposed system capacity, whichever is larger.

(6) Capacity
reservations are non-transferable from one customer generator to another.

(7) A
capacity reservation starts upon notification by the electric company to the successful
program participant that capacity has been awarded.

A retail electricity
consumer who has made a capacity reservation and who has executed all required agreements
with the electric company must be paid the effective volumetric incentive rate at
the time of enrollment for 100 percent of payable generation. Capacity reservation
applications and standard contracts must provide the volumetric incentive rate in
effect on the capacity reservation date.

(1) A capacity
reservation expires if a completed interconnection application is not filed within
two months of the reservation start date or if the system has not been installed
within twelve months of the reservation start date, unless a waiver is granted under
OAR 860-084-0000. Any delay resulting from the utility not completing required work
to connect the eligible system to the grid will be excluded from this 12-month installation
requirement.

(2) Once
the capacity reservation expires, the retail electricity consumer must newly apply
for a capacity reservation and will not be given preferential treatment.

(1) The electric
company must establish, in compliance with Commission order, a capacity application
process for both the net metering and competitive bidding options. The electric
company must provide the necessary instructions to complete a satisfactory capacity
application. Fees collected during the capacity application process must be refunded
to the retail electricity consumer if a capacity reservation is not secured.

(2) For
the purposes of these rules, an application package must include a capacity reservation
application, payment of fees required under OAR 860-084-0280, and an interconnection
application that complies with 860-084-0270(4)(a), (c), (d), (f), and (g). Electric
companies may not require a retail electricity consumer to provide the information
required by 860-084-0270(4)(b) and (4)(e) as part of this initial application
package.

(3) The
capacity reservation application must certify that the retail electricity consumer
has read and understands the standard contract established under the pilot program.
Standard contract forms must be provided to retail electricity consumers as part
of the application process.

(1) Each electric company must file, for Commission approval, a separate standard contract for the net metering and competitive bidding volumetric incentive rate programs as part of its volumetric incentive rate tariff filing.

(a) The standard contract will establish an agreement between the electric company and a retail electricity consumer under which the electric company will make volumetric incentive rate payments to participants for energy generated by solar photovoltaic systems installed in the service territory of the electric company for a 15-year period. After the initial 15-year period, the electric company may pay its prevailing avoided cost for energy generated by the solar photovoltaic systems.

(b) Contracts under the solar photovoltaic pilot programs may only be issued to retail electricity consumers of the electric company; these consumers must be eligible to participate in the pilots.

(2) Standard Contracts must include at least the following elements:

(a) Name and address of the retail electricity consumer and the installation address of the eligible system;

(b) Each standard contract must be based on the volumetric incentive rate (bid option) or volumetric incentive rate formula (net metering option) in place at the time of the capacity reservation for the retail electricity consumer;

(c) Each standard contract must require a retail electricity consumer installing capacity under the net metered option to transfer generation in excess of eligible energy to the low income bill assistance program of the electric company. Standard contracts must provide for certification by the retail electricity consumer that they are eligible to make wholesale sales of energy at market-based rates;

(d) Each standard contract must include a date of initiation and a date of contract expiration. If mutually agreed upon by the electric company and consumer, the contract may exceed 15 years;

(e) Each standard contract must include a section to record retail electricity consumer certifications that:

(A) Any investor in the qualifying system has not accepted or will not accept incentives from the Energy Trust of Oregon or Oregon state residential or business tax credits for the qualifying system covered by the contract, and

(B) The system and its individual components are new and have not been previously installed, and meet quality, reliability, and installation criteria approved by the Commission;

(f) Each standard contract must include a provision under which the retail electricity consumer agrees that the electric company can release lists of all participants in the pilot programs to the Oregon Department of Revenue, the Oregon Department of Energy, the Public Utility Commission, and the Energy Trust of Oregon. The standard contract must contain descriptions of the confidentiality requirements that those receiving this information must follow;

(g) Each standard contract must require the retail electricity consumer to agree to complete up to three surveys on the effectiveness of the pilot programs in order to remain eligible for participation in the pilot program. Each standard contract must also include the retail electricity consumer’s agreement that the electric company may release information obtained from the surveys to the Commission and the Energy Trust of Oregon;

(h) Monthly payments must be made directly to the retail electricity consumer or to a qualifying assignee;

(i) Each standard contract must allow a retail electricity consumer to assign payments to a single qualifying assignee. Contracts must allow the retail electricity consumer to change the assignee at any time during the contract term;

(j) Each standard contract must allow the transfer of an existing retail electricity consumer’s contract under the pilot program to another retail electricity consumer eligible to contract with the electric company under the pilot program, consistent with OAR 860-084-0130(3).

(k) Disclosure that payments under the volumetric incentive rate bid option may be taxable as income under Oregon and Federal Tax law and that an eligible system may be subject to property tax in the State of Oregon;

(l) Name and business address of solar installer or contractor, name and business address of system financer, and description of the photovoltaic equipment package;.

(m) For net metered systems, participants must certify that the system is sized such that their qualifying system complies with OAR 860-084-0100(2)(e).

(3) A retail electricity consumer found by the Commission to have made a false certification is no longer eligible for the Volumetric Incentive Rate Pilot Programs and any contract entered under the Volumetric Incentive Rate Pilot Programs is void.

(1) Volumetric incentive payments for payable energy must be paid no later than 45 days from the last day of the retail electricity consumer’s billing period. Retail electricity consumers may request that:

(a) Payments be paid directly to the consumer; the consumer will continue to receive a standard monthly bill for electricity purchased under the tariff; or

(b) Payments for energy generated be netted against the retail electricity consumer’s standard monthly bill and the retail electricity consumer receive or pay the resulting amount; or

(c) The qualified assignee identified on the standard contract be paid 100 percent of the volumetric incentive rate payment and the retail electricity consumer be billed separately for the retail electricity consumer’s monthly bill.

(2) The retail electricity consumer is responsible for the minimum monthly charge and other non-volumetric charges on the standard monthly bill.

(1) To be qualified
for interconnected operation, a qualifying system must be certified as complying
with the following standards as applicable:

(a) IEEE
standards; and

(b) UL
1741 Inverters, Converters, and Controllers for Use in Independent Power Systems
(January 2001).

(2) A
system is considered as certified to the standards of section (1) of this rule,
and the electric company may not require further design review, testing, or additional
equipment, if:

(a) The
system is a complete equipment package that has been submitted by a manufacturer
to a nationally recognized testing and certification laboratory, and has been tested
and listed by the laboratory for continuous interactive operation with an electric
distribution system in compliance with the applicable codes and standards listed
in section (1) of this rule; or

(b) The
system is an equipment package that includes a generator or other electric source
and the equipment package has been tested and listed as an integrated package in
compliance with the applicable codes and standards listed in section (1) of this
rule; or

(c) The
certified equipment package comprises only the interface components (switchgear,
inverters, or other interface devices), and the interconnection applicant has shown
that

(A) The
solar photovoltaic system being used is compatible with the equipment package;

(B) Testing
and listing of the solar photovoltaic generator being used, as performed by the
nationally recognized testing and certification laboratory, is consistent with the
testing and listing of the interface component equipment package; and

(C) The
testing and listing specified for the package is consistent with the applicable
codes and standards listed in section (1) of this rule.

(1) An eligible
system may not be interconnected to an electric company’s distribution system
before obtaining authorization from the electric company.

(2) Changes
affecting the nameplate capacity or the output capacity of the system authorized
in the agreement governing the contract require prior authorization from the electric
company.

(4) Interconnection
applications must be provided by the electric company and posted on the electric
company’s website. The submission of a completed interconnection application
initiates interconnection review. The application must include the following:

(a) The
name of the applicant and the electric company;

(b) The
type and specifications of each component of the qualified solar photovoltaic system;

(d) The
name of the installer of the qualified solar photovoltaic system;

(e) Equipment
certifications;

(f) The
anticipated operation date of the solar photovoltaic system; and

(g) Other
information the utility deems necessary to comply with the solar photovoltaic pilot
program interconnection rules.

(5) Within
three business days of receiving the interconnection application, the electric company
must provide the applicant a written notice of receipt stating whether the application
meets the established criteria.

(a) If
the application does not meet established criteria, the written notice must include
a list of all of the information needed to complete the application.

(b) If
the number of applications in a regular business week exceeds 20, the electric company
must inform the customers that the written-notice period is ten business days.

(6) Each
electric company must designate an employee or office from which an applicant can
obtain application forms and other information necessary to complete the application
process; the electric company must post the application form and the necessary information
on its website. Upon request, the electric company must provide all relevant forms,
documents, and technical requirements for submittal of an application that meets
established criteria for an interconnection application under these solar photovoltaic
pilot program rules, as well as specific information necessary to contact the electric
company representative assigned to review the application.

(7) A
person may also request information about the feasibility of interconnecting a qualifying
system before filing an application for capacity reservation or interconnection.
The information provided by the electric company in response to this request must
include relevant existing studies and other materials that may be used to understand
the feasibility of interconnecting a solar photovoltaic facility at a particular
point on the electric company’s distribution system. The electric company
must comply with reasonable requests for access to or copies of this information,
except to the extent that providing these materials would violate security requirements,
confidentiality obligations to third parties, or federal or state regulations. The
electric company may require a person to sign a confidentiality agreement if required
to protect confidential or proprietary information. A person requesting information
under this section must reimburse the electric company for the reasonable costs
of gathering and copying the requested information.

(8) The
electric company is not responsible for the cost of determining the rating of equipment
on the customer side of the meter.

(1) For a Level 1 interconnection review, the electric company may not charge an application, or other fee, unless otherwise directed by the Commission. However, if an application for Level 1 interconnection review is denied because it does not meet the requirements for Level 1 interconnection review and the applicant resubmits the application under another review procedure, the electric company may impose a fee for the resubmitted application.

(2) For a Level 2 interconnection review, the electric company may charge fees of up to $50.00 plus $1.00 per kilowatt of the qualifying system's capacity, plus the reasonable cost of any required minor modifications to the electric distribution system or additional review. Costs for such minor modifications or additional review will be based on the electric company’s non-binding, good faith estimates and the ultimate actual installed costs. Costs for engineering work done as part of any additional review will not exceed $100.00 per hour. An electric company may adjust the $100.00 hourly rate once in January of each year to account for inflation and deflation as measured by the Consumer Price Index.

(3) For a Level 3 interconnection review, the electric company may charge fees of up to $100.00 plus $2.00 per kilowatt of the qualifying system’s capacity, as well as charges for actual time spent on any required impact or facilities studies. Costs for engineering work done as part of an impact study or interconnection facilities study will not exceed $100.00 per hour. An electric company may adjust the $100.00 hourly rate once in January of each year to account for inflation and deflation as measured by the Consumer Price Index. If the electric company must install facilities in order to accommodate the interconnection of the qualifying system, the cost of such facilities will be the responsibility of the applicant.

(4) Interconnected net metered systems must be equipped with two meters: metering equipment that can measure the flow of electricity in both directions (complying with ANSI C12.1 standards and OAR 860-023-0015) to replace the existing customer meter, and a second meter that can measure the total output of the qualifying system. Interconnected stand-alone systems using the bidding process must be equipped with metering equipment that can measure the flow of electricity in both directions (complying with ANSI C12.1 standards and OAR 860-023-0015). The electric company will install the required metering equipment at the electric company’s expense for both the net metered and stand-alone system.

(a) The electric company constructs, owns, operates, and maintains all meters and applicable interconnection facilities on the company side of the retail electric consumer’s meter, including, the second meter installed to measure the total output of the qualifying system.

(b) The electric company must charge an additional monthly service charge to the retail electricity customer for the additional meter used to measure the total output of the qualifying system, as established by Commission order.

(5) An eligible participant who is reinstalling a contracted system and is eligible to continue in the solar photovoltaic pilot program under an existing standard contract must pay the expense of interconnection facilities, required additions or modifications to the electric distribution system, interconnection review, or system upgrades in the new location as applicable.

(1) An eligible system is eligible for Level 1 interconnection review if:

(a) The facility is inverter-based; and

(b) The facility has a capacity of 25 kilowatts or less.

(2) The electric company must approve interconnection under the Level 1 interconnection review procedure if:

(a) The aggregate generation capacity on the distribution circuit to which the eligible system will interconnect, including the capacity of the eligible system, may not contribute more than 10 percent to the distribution circuit's maximum fault current at the point on the high voltage (primary) level that is nearest the proposed point of common coupling;

(b) An eligible system's point of common coupling may not be on a transmission line, a spot network, or an area network;

(c) If an eligible system is to be connected to a radial distribution circuit, the aggregate generation capacity connected to the circuit, including that of the eligible system, may not exceed 15 percent of the circuit's total annual peak load, as most recently measured at the substation;

(d) If an eligible system is to be connected to a single-phase shared secondary, the aggregate generation capacity connected to the shared secondary, including the eligible system, may not exceed 20 kilovolt-amps; and

(e) If a single-phase eligible system is to be connected to a transformer center tap neutral of a 240 volt service, the addition of the eligible system may not create a current imbalance between the two sides of the 240 volt service of more than 20 percent of nameplate rating of the service transformer.

(3) Within 10 business days after the electric company notifies a Level 1 applicant that the application is complete, the electric company must notify the applicant that:

(a) The eligible system meets all applicable criteria and the interconnection is approved upon installation of any required meter upgrade, completion of any required inspection of the facility, and execution of an interconnection agreement; or

(b) The eligible system has failed to meet one or more of the applicable criteria and the interconnection application is denied.

(4) If an electric company does not notify a Level 1 applicant in writing or by electronic mail whether the interconnection is approved or denied within 20 business days after the receipt of an application, the interconnection will be deemed approved. Interconnections approved under this section remain subject to section (7) of this rule.

(5) Within three business days after sending the notice to an applicant that the proposed interconnection meets the Level 1 requirements, an electric company must notify the applicant:

(a) Whether an inspection of the eligible system for compliance with these interconnection rules is required prior to the operation of the system; and

(b) That an interconnection agreement is required for the eligible system. The electric company must also execute and send to the applicant a Level 1 interconnection agreement, unless the applicant has already submitted such an agreement with its application for interconnection.

(6) On receipt of an executed interconnection agreement from the applicant and satisfactory completion of any required inspection, the electric company must approve the interconnection, conditioned on compliance with all applicable building codes.

(7) The retail electric customer must notify the electric company of the anticipated start date for operation of the eligible system at least five business days prior to starting operation, either through the submittal of the interconnection agreement or in a separate notice. If the electric company requires an inspection of the eligible system, the applicant may not begin operating the facility until satisfactory completion of the inspection.

(8) If an application for Level 1 interconnection review is denied because it does not meet one or more of the applicable requirements in this rule, an applicant may resubmit the application under the Level 2 or Level 3 interconnection review procedure, as appropriate.

(1) An electric company must apply the following Level 2 interconnection review procedure for an application to interconnect an eligible system that meets the following criteria:

(a) The facility has a capacity of 500 kilowatts or less; and

(b) The facility does not qualify for or failed to meet applicable Level 1 interconnection review procedures.

(2) The electric company must approve interconnection under the Level 2 interconnection review procedure if:

(a) The aggregate generation capacity on the distribution circuit to which the eligible system will interconnect, including the capacity of the eligible system, will not cause any distribution protective equipment (including, but not limited to, substation breakers, fuse cutouts, and line reclosers), or customer equipment on the electric distribution system, to exceed 90 percent of the short circuit interrupting capability of the equipment. In addition, an eligible system may not be connected to a circuit that already exceeds 90 percent of the short circuit interrupting capability, prior to interconnection of the facility;

(b) If there are posted transient stability limits to generating units located in the general electrical vicinity of the proposed point of common coupling, including, but not limited to within three or four transmission voltage level busses, the aggregate generation capacity, including the eligible system, connected to the distribution low voltage side of the substation transformer feeding the distribution circuit containing the point of common coupling may not exceed 10 megawatts;

(c) The aggregate generation capacity connected to the distribution circuit, including the eligible system, may not contribute more than 10 percent to the distribution circuit's maximum fault current at the point on the high voltage (primary) level nearest the proposed point of common coupling;

(d) If an eligible system is to be connected to a radial distribution circuit, the aggregate generation capacity connected to the electric distribution system by non-electric company sources, including the eligible system, may not exceed 15 percent of the total circuit annual peak load. For the purposes of this subsection, annual peak load will be based on measurements taken over the 12 months previous to the submittal of the application, measured for the circuit at the substation nearest to the eligible system;

(e) If an eligible system is to be connected to three-phase, three wire primary electric company distribution lines, a three-phase or single-phase generator must be connected phase-to-phase;

(f) If an eligible system is to be connected to three-phase, four wire primary electric company distribution lines, a three-phase or single-phase generator must be connected line-to-neutral and must be effectively grounded;

(g) If an eligible system is to be connected to a single-phase shared secondary, the aggregate generation capacity on the shared secondary, including the eligible system, may not exceed 20 kilovolt-amps;

(h) If an eligible system is single-phase and is to be connected to a transformer center tap neutral of a 240 volt service, the addition of the eligible system may not create a current imbalance between the two sides of the 240 volt service that is greater than 20 percent of the nameplate rating of the service transformer;

(i) An eligible system's point of common coupling may not be on a transmission line; and

(j) If an eligible system's proposed point of common coupling is on a spot or area network, the interconnection must meet the following additional requirements:

(A) For an eligible system that will be connected to a spot network circuit, the aggregate generation capacity connected to that spot network from the eligible system, and any generating facilities, may not exceed five percent of the spot network's maximum load;

(B) For an eligible system that utilizes inverter-based protective functions, which will be connected to an area network, the eligible system, combined with any other generating facilities on the load side of network protective devices, may not exceed 10 percent of the minimum annual load on the network, or 500 kilowatts, whichever is less. The percent of minimum load must be calculated based on the minimum load occurring during an off-peak daylight period; and

(C) For an eligible system that will be connected to a spot or an area network that does not utilize inverter-based protective functions, or for an inverter-based eligible system that does not meet the requirements of paragraphs (A) or (B) of this subsection, the eligible system must utilize low forward power relays or other protection devices that ensure no export of power from the eligible system, including inadvertent export (under fault conditions) that could adversely affect protective devices on the network.

(3) Within 15 business days after notifying a Level 2 applicant that the application is complete, the electric company must perform an initial review of the proposed interconnection to determine whether the interconnection meets the applicable criteria. During this initial review, the electric company may, at its own expense, conduct any studies or tests it deems necessary to evaluate the proposed interconnection and provide notice to the applicant of one of the following determinations:

(a) The eligible system meets the applicable requirements and that interconnection will be approved following any required inspection of the facility and fully executed interconnection agreement. Within three business days after this notice, the electric company must provide the applicant with an executable interconnection agreement;

(b) The eligible system failed to meet one or more of the applicable requirements, but the electric company determined that the eligible system may be interconnected consistent with safety, reliability, and power quality. In this case, the electric company must notify the applicant that the interconnection will be approved following any required inspection of the facility and fully executed interconnection agreement. Within five business days after this notice, the electric company must provide the applicant with an executable interconnection agreement; or

(c) The eligible system failed to meet one or more of the applicable requirements, and that additional review would not enable the electric company to determine that the eligible system could be interconnected consistent with safety, reliability, and power quality. In such a case, the electric company must notify the applicant that the interconnection application has been denied and must provide an explanation of the reason(s) for the denial, including a list of additional information, or modifications to the eligible system, or both, which would be required in order to obtain an approval under Level 2 interconnection procedures.

(4) An applicant that receives an interconnection agreement under subsection (3)(a) or (3)(b) of this rule must:

(a) Execute the agreement and return it to the electric company at least 10 business days prior to starting operation of the eligible system (unless the electric company does not so require); and

(b) Indicate to the electric company the anticipated start date for operation of the eligible system.

(5) The electric company may require an electric company inspection of an eligible system for compliance with these solar photovoltaic rules prior to operation, and may require and arrange for witness of commissioning tests as set forth in IEEE standards. The electric company must schedule any inspections or tests under this section promptly and within a reasonable time after submittal of the application. The applicant may not begin operating the eligible system until after the inspection and testing is completed.

(6) Approval of interconnected operation of any Level 2 eligible system must be conditioned on all of the following occurring:

(a) Approval of the interconnection by the electrical code official with jurisdiction over the interconnection;

(b) Successful completion of any electric company inspection or witnessing of commissioning tests, or both, requested by the electric company; and

(c) Passing of the planned start date provided by the applicant.

(7) If an application for Level 2 interconnection review is denied because it does not meet one or more of the requirements of this rule, the applicant may resubmit the application under the Level 3 interconnection review procedure.

(1) The electric company must apply the Level 3 review procedure for an application to interconnect an eligible system that meets the following criteria:

(a) The facility has a capacity of 500 kilowatts or less; and

(b) The facility does not qualify or failed to meet Level 2 interconnection review procedures.

(2) Following receipt of a Level 3 application and within three business days of a request from the applicant, the electric company must provide pertinent information to the applicant, such as the available fault current at the proposed interconnection location, the existing peak loading on the lines in the general vicinity of the eligible system, and the configuration of the distribution lines at the proposed point of common coupling.

(3) Within seven business days after receiving a complete application for Level 3 interconnection review, the electric company must conduct an impact study which will include a non-binding, good faith cost estimate. The impact study must be conducted in accordance with good utility practice and must:

(a) Detail the impacts to the electric distribution system that would result if the eligible system were interconnected without modifications to either the eligible system or to the electric distribution system;

(b) Identify any modifications to the electric company's electric distribution system that would be necessary to accommodate the proposed interconnection; and

(c) Focus on power flows and utility protective devices, including control requirements; and

(d) Include the following elements, as applicable:

(A) A load flow study;

(B) A short-circuit study;

(C) A circuit protection and coordination study;

(D) The impact on the operation of the electric distribution system;

(E) A stability study, along with the conditions that would justify including this element in the impact study;

(F) A voltage collapse study, along with the conditions that would justify including this element in the impact study.

(4) The electric company must complete the impact study and must notify the applicant within 30 calendar days of one of the following results:

(a) Only minor modifications to the electric company's electric distribution system are necessary to accommodate interconnection. In such a case, the electric company will send the applicant an interconnection agreement that details the scope of the necessary modifications and a non-binding, good faith estimate of its cost; or

(b) Substantial modifications to the electric company’s electric distribution system are necessary to accommodate the proposed interconnection. In such a case, the electric company must provide a non-binding, good faith estimate of the cost of the modifications, which must be accurate to within plus or minus 25 percent. In addition, the electric company must offer to conduct, at the applicant’s expense, an interconnection facilities study that must identify the types and cost of equipment needed to safely interconnect the applicant's eligible system.

(5) If the proposed interconnection may affect electric transmission or delivery systems other than those controlled by the electric company, operators of those other systems may require additional studies to determine the potential impact of the interconnection on those systems. If such additional studies are required, the electric company must coordinate the studies but is not responsible for their timing.

(6) If an applicant requests a facilities study under subsection (4)(b), the electric company must provide an interconnection facilities study agreement. The interconnection facilities study agreement must describe the work to be undertaken in the interconnection facilities study and must include a non-binding, good faith estimate of the cost to the applicant for completion of the study. Upon the execution by the applicant of the interconnection facilities study agreement, the electric company will conduct an interconnection facilities study to identify the facilities necessary to safely interconnect the eligible system with the electric company’s electric distribution system, and to propose a non-binding, good faith estimate of the cost of those facilities and the time required to build and install those facilities.

(7) Upon completion of an interconnection facilities study, the electric company must provide the applicant with the results of the study and an executable interconnection agreement. The agreement must list the conditions and facilities necessary for the eligible system to safely interconnect with the electric company’s electric distribution system, and must include a non-binding, good faith estimate of the cost of those facilities and the estimated time required to build and install those facilities.

(8) If the applicant wishes to interconnect, it must execute the interconnection agreement and return it to the electric company at least 10 business days prior to starting operation of the eligible system (unless the electric company does not so require), pay a deposit of not more than 50 percent of the estimated cost of the facilities identified in the interconnection facilities study, complete installation of the eligible system, and agree to pay the public utility the actual installed cost of the facilities needed to interconnect as identified in the interconnection facilities study.

(9) Within 15 business days after notice from the applicant that the eligible system has been installed, the electric company must inspect the eligible system and must arrange to witness any commissioning tests required under IEEE standards. The electric company and the applicant must select a date by mutual agreement for the electric company to witness commissioning tests.

(10) If the eligible system satisfactorily passes required commissioning tests, if any, the electric company must notify the applicant in writing, within three business days after the tests, of one of the following:

(a) The interconnection is approved and the eligible system may begin operation; or

(b) The interconnection facilities study identified necessary construction that has not been completed, the date upon which the construction must be completed, and the date when the eligible system may begin operation.

(11) If the commissioning tests are not satisfactory, the applicant must repair or replace the unsatisfactory equipment to reschedule a commissioning test.

A contracted
system must include and maintain a manual disconnect switch that will disconnect
the solar photovoltaic system from the electric company’s system.

(1) The
disconnect switch must be a lockable, load-break switch that plainly indicates whether
it is in the open or closed position.

(2) The
disconnect switch must be readily accessible to the electric company at all times
and be located within 10 feet of the electric company meter. The disconnect switch
may be located more than 10 feet from the electric company meter if permanent instructions
are posted at the meter indicating the precise location of the disconnect switch.
The electric company must approve the location of the disconnect switch prior to
the installation of the facility.

(3) The
retail electricity consumer must install and maintain the required disconnect switch
at the retail electricity consumer’s expense.

(4) For
customer services of 600 volts or less, an electric company may not require a disconnect
switch for an eligible system that is inverter-based with a maximum rating as shown
below.

(1) Once a contracted system has been approved under these solar photovoltaic interconnection rules, the electric company may not require a retail electricity consumer to test or perform maintenance on its facility except for:

(a) An annual test in which the contracted system is disconnected from the electric company's equipment to ensure that the inverter stops delivering power to the grid;

(b) Any manufacturer-recommended testing or maintenance;

(c) Any post-installation testing necessary to ensure compliance with IEEE standards or to ensure safety; and

(d) Testing required if the retail electricity customer replaces a major equipment component that is different from the originally installed model.

(2) When a contracted system undergoes maintenance or testing in accordance with the requirements of these solar photovoltaic interconnection rules, the retail electricity consumer must retain written records for seven years documenting the maintenance and the results of testing.

(3) An electric company has the right to inspect a contracted system after interconnection approval is granted, at reasonable hours and with reasonable prior notice to the retail electricity consumer. If the electric company discovers that the contracted system is not in compliance with the requirements of these solar photovoltaic interconnection rules, the electric company may require the retail electricity consumer to disconnect the contracted system until compliance is achieved.

(4) The retail electricity customers’ electric service may be disconnected by the public utility entirely if the contracted system must be physically disconnected for any reason.

(1) Each electric
company must pay the retail electricity consumer on a monthly basis for payable
generation up to the consumer’s actual usage in the month. Any excess generation
in the month transfers to the next month’s eligible generation. At the end
of a generation year, any remaining excess generation is donated to the low income
bill assistance.

(2) The
default generation year is April 1to March 31. For irrigation and agriculture customers,
the default generation year is November 1 to October 31.

(3) The
monthly incentive payment equals the product of the volumetric incentive rate specified
in the standard contract minus the retail rate in effect at the time of payment
for eligible generation for the month.

(1) A retail
electricity consumer participating under the volumetric incentive rate bidding option
of the pilot program receives a payment that equals the product of the payable generation
delivered to the electric company and the volumetric incentive rate per kilowatt-hour
established through the consumer’s successful bid in the pilot program.

(2) Each
company will conduct a volumetric incentive rate bidding process with capacity awarded
in the second month of each pilot year, or as otherwise directed by the Commission,
through a request for proposal process approved by the Commission.

(1) On November 1 of 2010, 2012, and 2014, each electric company must file, for review in a Commission proceeding, its estimate of the 15-year levelized resource value for the company, along with supporting work papers.

(2) For the purpose of determining payments to retail electricity consumers at the end of the 15-year contract term, each electric utility must file, beginning January 1, 2025, and every January 1 thereafter, its estimates of the annual resource value for the company for each of the next five years.

(3) A resource value may be established for small-scale, medium-scale, and large-scale systems and may be differentiated by remote location or location central to the system load, as directed by the Commission.

(1) An electric company may recover in rates all costs prudently incurred to offer the pilot program established under these rules, including, but not limited to, costs not otherwise reflected in rates for electricity usage related to:

(a) Payments for the output of contracted systems, and

(b) Data collection and analysis for assessment of the company’s pilot program.

(2) On November 1 of 2010, 2012, and 2014, and as otherwise directed by the Commission, each electric company must file for review, in a Commission proceeding, its estimates of the rate impact of pilot program participation, for each customer class, along with supporting work papers.

(3) The Commission may establish total generator nameplate capacity limits for an electric company so that the rate impact of the pilot program for any customer class does not exceed 0.25 percent of the company’s revenue requirement for the class in any year.

An electric company may request recovery of prudently incurred costs associated with compliance with the solar photovoltaic pilot program requirements. Mechanisms for recovery of cost associated with compliance will be established by Commission order.

Except as provided
in OAR 860-084-0440, each electric company must collect from the retail electricity
consumer participating in the pilot program data on the installed solar photovoltaic
system. The collected data elements must include, but are not limited to:

(14) Electric
companies must collect data on the time to interconnection agreement and conduct
pilot program satisfaction surveys in order to improve capacity reservation and
interconnection processes over the pilot program. Data collection and surveys must
include:

(a) Interconnection
agreements that have not been negotiated between the electricity company and the
retail electricity consumer within six months after an application for interconnection
has been filed; or

(1) The participant
agrees to the confidential release of information from participant surveys and pilot
program applications to the organizations listed in section (2) of this rule.

(2) Each
electric company must send a list of all reserved and contracted systems that have
completed the release of confidential information to the Energy Trust of Oregon,
the Oregon Department of Revenue, or the Oregon Department of Energy, upon request
by each organization. Data in this list must include the following minimum information:

(a) Installation
location of system;

(b) Nameplate
capacity of installed system;

(c) Name,
business name, and business address of contractor installing system;

(1) Each electric
company must verify that the data collected pursuant to OAR 860-084-0400 and 860-084-0420
has been recorded in an appropriate electronic database prior to making volumetric
incentive rate payments to participating retail electricity consumers.

(2) Upon
request, each electric company must provide the data collected under OAR 860-084-0400
and 860-084-0420, in a format established by the Commission. Reports that include
this raw data and a summary of this data for the pilot program to date, must be
provided to the Oregon Department of Energy, the Energy Trust of Oregon, the Oregon
Department of Revenue, and the Commission, bi-annually, on the 15th day in February
and August.

(3) Each
electric company must provide the Commission or the Oregon Department of Energy
location information that will enable one of these state agencies to make graphically
visible, on a publically accessible website, the general locations and sizes of
reserved and contracted systems of all electric companies within the state of Oregon.
This information must not include consumer names or installation addresses or total
capacity deployed to date.

(a) Proposals
for the design and execution of surveys to measure participant satisfaction with
and recommendations for improving the pilot program processes;

(b) Proposals
for the design and execution of surveys to understand participant decision processes
in choosing between the volumetric incentive rate program and the existing net metering
program;

(c) Comments
on Commission recommendations for regulatory policy changes that may increase the
use of solar photovoltaic systems, make solar photovoltaic systems more affordable,
reduce the cost of incentives to utility customers, or promote the development of
the solar industry in Oregon; and

(d) Additions
to the list of required data to be collected under OAR 860-084-0400.

(2) Each
electric company may enter into a contract with the Energy Trust of Oregon to provide
the data collection and summary services required by OAR 860-084-0400 through 860-084-0440.
An electric company may also contract with the Energy Trust of Oregon to administer
pilot programs, including capacity reservation services, survey execution, or program
evaluation. The Commission may direct the electric companies to contract with the
Energy Trust of Oregon if the Commission finds that the costs to administer individual
pilot programs are unreasonable.

The Commission must open a docket on or before November 1 of 2010, 2012, and 2014 to receive public comment and recommendations on the draft reports prepared by Commission staff regarding the pilot programs.

The official copy of an Oregon Administrative Rule is
contained in the Administrative Order filed at the Archives Division,
800 Summer St. NE, Salem, Oregon 97310. Any discrepancies with the
published version are satisfied in favor of the Administrative Order.
The Oregon Administrative Rules and the Oregon Bulletin are
copyrighted by the Oregon Secretary of State. Terms
and Conditions of Use